Wellbores utilizing fiber optic-based sensors and operating devices

ABSTRACT

This invention provides a method for controlling production operations using fiber optic devices. An optical fiber carrying fiber-optic sensors is deployed downhole to provide information about downhole conditions. Parameters related to the chemicals being used for surface treatments are measured in real time and on-line, and these measured parameters are used to control the dosage of chemicals into the surface treatment system. The information is also used to control downhole devices that may be a packer, choke, sliding sleeve, perforating device, flow control valve, completion device, an anchor or any other device. Provision is also made for control of secondary recovery operations online using the downhole sensors to monitor the reservoir conditions. The present invention also provides a method of generating motive power in a wellbore utilizing optical energy. This can be done directly or indirectly, e.g., by first producing electrical energy that is then converted to another form of energy.

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority from Provisional U.S. PatentApplications Ser. Nos. 60/045,354 filed on May 2, 1997; 60/048,989 filedon Jun. 9, 1997; 60/052,042 filed on Jul. 9, 1997; 60/062,953 filed onOct. 10, 1997; 67/073425 filed on Feb. 2, 1998; and 60/079,446 filed onMar. 26, 1998. Reference is also made to a United States PatentApplication entitled “Monitoring of Downhole Parameters and ToolsUtilizing Fiber Optics” filed on the same date as the presentapplication under Attorney Docket No. 414-9450 US, the contents of whichare incorporated here by reference.

BACKGROUND OF THE INVENTION

[0002] 1. Field of the Invention

[0003] This invention relates generally to oilfield operations and moreparticularly to the downhole apparatus utilizing fiber optic sensors anduse of same in monitoring the condition of downhole equipment,monitoring certain geological conditions, reservoir monitoring andremedial operations.

[0004] 2. Background of the Art

[0005] A variety of techniques have been utilized for monitoringwellbores during completion and production of wellbores, reservoirconditions, estimating quantities of hydrocarbons (oil and gas),operating downhole devices in the wellbores, and determining thephysical condition of the wellbore and downhole devices.

[0006] Reservoir monitoring typically involves determining certaindownhole parameters in producing wellbores at various locations in oneor more producing wellbores in a field, typically over extended timeperiods. Wireline tools are most commonly utilized to obtain suchmeasurements, which involves transporting the wireline tools to thewellsite, conveying the tools into the wellbores, shutting down theproduction and making measurements over extended periods of time andprocessing the resultant data at the surface. Seismic methods wherein aplurality of sensors are placed on the earth's surface and a sourceplaced at the surface or downhole are utilized to provide maps ofsubsurface structure. Such information is used to update prior seismicmaps to monitor the reservoir or field conditions. Updating existing 3-Dseismic maps over time is referred to in industry as “4-D Seismic”. Theabove described methods are very expensive. The wireline methods areutilized at relatively large time intervals, thereby not providingcontinuous information about the wellbore condition or that of thesurrounding formations.

[0007] Placement of permanent sensors in the wellbore, such astemperature sensors, pressure sensors, accelerometers and hydrophoneshas been proposed to obtain continuous wellbore and formationinformation. A separate sensor is utilized for each type of parameter tobe determined. To obtain such measurements from the entire usefulsegments of each wellbore, which may have multi-lateral wellbores,requires using a large number of sensors, which requires a large amountof power, data acquisition equipment and relatively large space in thewellbore: this may be impractical or prohibitively expensive.

[0008] Once the information has been obtained, it is desirable tomanipulate downhole devices such as completion and production strings.Prior art methods for performing such functions rely on the use ofelectrically operated devices with signals for their operationcommunicated through electrical cables. Because of the harsh operatingconditions downhole, electrical cables are subject to degradation. Inaddition, due to long electrical path lengths for downhole devices,cable resistance becomes significant unless large cables are used. Thisis difficult to do within the limited space available in productionstrings. In addition, due to the high resistance, power requirementsalso become large.

[0009] One particular arrangement in which operation of numerousdownhole devices becomes necessary is in secondary recovery. Injectionwells have, of course, been employed for many years in order to flushresidual oil in a formation toward a production well and increase yieldfrom the area. A common injection scenario is to pump steam d wn aninjection well and into the formation which functions both to heat theoil in the formation and force its movement through the practice ofsteam flooding. In some cases, heating is not necessary as the residualoil is in a flowable form, however in some situations the oil is in sucha viscous form that it requires heating in order to flow. Thus, by usingsteam one accomplishes both objectives of the injection well: 1) toforce residual oil toward the production well and 2) to heat any highlyviscous oil deposits in order mobilize such oil to flow ahead of theflood front toward the production well. As is well known to the art, oneof the most common drawbacks of employing the method above noted withrespect to injection wells is an occurrence commonly identified as“breakthrough”. Breakthrough occurs when a portion of the flood frontreaches the production well. As happens the flood water remaining in thereservoir will generally tend to travel the path of least resistance andwill follow the breakthrough channel to the production well. At thispoint, movement of the viscous oil ends. Precisely when and where thebreakthrough will occur depends upon water/oil mobility ratio, thelithology, the porosity and permeability of the formation as well as thedepth thereof. Moreover, other geologic conditions such as faults andunconformities also affect the in-situ sweep efficiency.

[0010] While careful examination of the formation by skilled geologistscan yield a reasonable understanding of the characteristics thereof andtherefore deduce a plausible scenario of the way the flood front willmove, it has not heretofore been known to monitor precisely the locationof the flood front as a whole or as individual sections thereof. By somonitoring the flood front, it is possible to direct greater or lesserflow to different areas in the reservoir, as desired, by adjustment ofthe volume and location of both injection and production, hencecontrolling overall sweep efficiency. By careful control of the floodfront, it can be maintained in a controlled, non fingered profile. Byavoiding premature breakthrough the flooding operation is effective formore of the total formation volume, and thus efficiency in theproduction of oil is improved.

[0011] In production wells, chemicals are often injected downhole totreat the producing fluids. However, it can be difficult to monitor andcontrol such chemical injection in real time. Similarly, chemicals aretypically used at the surface to treat the produced hydrocarbons (i.e.,to break down emulsions) and to inhibit corrosion. However, it can bedifficult to monitor and control such treatment in real time.

[0012] The present invention addresses the above-described deficienciesof the prior art and provides apparatus and methods which utilizesensors (such as fiber optic sensors), wherein each sensor can provideinformation about more than one parameter to perform a variety offunctions. The sensors are used to measure parameters related to thechemical introduction in real time so that the chemical treatment systemcan be accurately monitored and controlled.

[0013] The present invention addresses the above-described deficienciesof prior art and provides apparatus and methods which utilize fiberoptic sensors, wherein each sensor can provide information about morethan one parameter to perform a variety of functions. The sensors may beplaced along any length of the wellbore. Sensor segments, eachcontaining one or more sensors, may be coupled to form an active sectionthat may be disposed in the casing for continuous monitoring of thewellbore. Sensors may be distributed in a wellbore or multiple wellboresfor determining parameters of interest. Hermetically sealed opticalfibers coated with high temperature resistant materials are commerciallyavailable. Single or multi-mode sensors can be fabricated along thelength of such optical fibers. Such sensors include temperature,pressure and vibration sensors. Such sensors can withstand hightemperatures in excess of 250 degrees Celsius for extended time periodsand thus have been found to be useful in wellbore applications. Anoptical fiber is a special case of an optical waveguide and in mostapplications, other types of optical waveguides, including thosecontaining a fluid, can usually be substituted for optical fiber.

[0014] The present invention provides certain completion and productionstrings that utilize fiber optical waveguide based sensors and devices.The invention also provides a method of generating electrical powerdownhole, utilizing light cells installed in the wellbore.

SUMMARY OF THE INVENTION

[0015] This invention uses fiber optic sensors to make measurements ofdownhole conditions in a producing borehole. The measurements includetemperature and pressure measurements; flow measurements related to thepresence of solids and of corrosion, scale and paraffin buildup;measurements of fluid levels; displacement; vibration; rotation;acceleration; velocity; chemical species; radiation; pH values;humidity; density; and of electromagnetic and acoustic wavefields. Thesemeasurements are used for activating a hydraulically-operated devicedownhole and deploying a fiber optic sensor line utilizing a commonfluid conduit. A return hydraulic conduit is placed along the length ofa completion string. The hydraulic conduit is coupled to thehydraulically-operated device in a manner such that when fluid underpressure is supplied to the conduit, it would actuate the device. Thestring is placed or conveyed in the wellbore. Fiber optic cable carryinga number of sensors is forced into one end of the conduit until itreturns at the surface at the other end. Light source and signalprocessing equipment is installed at the surface. The fluid is suppliedunder sufficient pressure to activate the device when desired. Thehydraulically-operated device may be a packer, choke, sliding sleeve,perforating device, flow control valve, completion device, an anchor orany other device. The fiber optic sensors carried by the cable mayinclude pressure sensors, temperature sensors, vibration sensors, andflow measurement sensors.

[0016] This invention also provides a method of controlling productionfrom a wellbore. A production string carrying an electrical submersiblepump is preferably made at the surface. An optical fiber carrying aplurality of fiber optic sensors is placed along a high voltage linethat supplies power to the pump for taking measurements along thewellbore length. In one configuration, a portion of the fiber carryingselected sensors is deployed below the pump. Such sensors may include atemperature sensor, a pressure sensor and a flow rate measurementsensor. These sensors effectively replace the instrumentation packageusually installed for the pump.

[0017] In an application to control of injection wells, the inventionprovides significantly more information to well operators thus enhancingoil recovery to a degree not heretofore known. This is accomplished byproviding real time information about the formation itself and the floodfront by providing permanent downhole sensors capable of sensing changesin the swept and unswept formation and/or the progression of the floodfront. Preferably a plurality of sensors would be employed to provideinformation about discrete portions of strata surrounding the injectionwell. This provides a more detailed data set regarding the well(s) andsurrounding conditions. The sensors are, preferably, connected to aprocessor either downhole or at the surface for processing ofinformation. Moreover, in a preferred embodiment the sensors areconnected to computer processors which are also connected to sensors ina production well (which are similar to those disclosed in U.S. Pat. No.5,597,042 which is fully incorporated herein by reference) to allow theproduction well to “talk” directly to the related injection well(s) toprovide an extremely efficient real time operation. Sensors employedwill be to sense temperature, pressure, flow rate, electrical andacoustic conductivity, density and to detect various light transmissionand reflection phenomena. All of these sensor types are availablecommercially in various ranges and sensitivities which are selectable byone of ordinary skill in the art depending upon particular conditionsknown to exist in a particular well operation. Specific pressuremeasurements will also include pressure(s) at the exit valve(s) down theinjection well and at the pump which may be located downhole or at thesurface. Measuring said pressure at key locations such as at the outlet,upstream of the valve(s) near the pump will provide information aboutthe speed, volume, direction, etc. at/in which the waterflood front (orother fluid) is moving. Large differences in the pressure from higher tolower over a short period of time could indicate a breakthrough.Conversely, pressure from lower to higher over short periods of timecould indicate that the flood front had hit a barrier. These conditionsare, of course, familiar to one of skill in the art but heretofore farless would have been known since no workable system for measuring theparameters existed. Therefore the present invention since it increasesknowledge, increases productivity.

[0018] Referring now to the measurement of density as noted above, thepresent invention uses fluid densities to monitor the flood front fromthe trailing end. As will be appreciated from the detailed discussionherein, the interface between the flood front and the hydrocarbon fluidprovides an acoustic barrier from which a signal can be reflected. Thusby generating acoustic signals and mapping the reflection, the profileof the front is generated in 4D i.e., three dimensions over time.

[0019] The distributed sensors of this invention find particular utilityin the monitoring and control of various chemicals which are injectedinto the well. Such chemicals are needed downhol to address a largenumber of known problems such as for scale inhibition and variouspretreatments of the fluid being produced. In accordance with thepresent invention, a chemical injection monitoring and control systemincludes the placement of one or more sensors downhole in the producingzone for measuring the chemical properties of the produced fluid as wellas for measuring other downhole parameters of interest. These sensorsare preferably fiber optic based and are formed from a sol gel matrixand provide a high temperature, reliable and relatively inexpensiveindicator of the desired chemical parameter. The downhole chemicalsensors may be associated with a network of distributed fiber opticsensors positioned along the wellbore for measuring pressure,temperature and/or flow. Surface and/or downhole controllers receiveinput from the several downhole sensors, and in response thereto,control the injection of chemicals into the borehole.

[0020] In still another feature of this invention, parameters related tothe chemical being used for surface treatments are measured in real timeand on-line, and these measured parameters are used to control thedosage of chemicals into the surface treatment system.

[0021] Another aspect of the present invention provides a fiber opticdevice (light actuated transducer) for generating mechanical energy andmethods of using such energy at the well site. The device contains afluid that rapidly expands in an enclosure upon the application ofoptical energy. The expansion of the fluid moves a piston in theenclosure. The fluid contracts and the piston is pushed back to itsoriginal position by a force device such as spring. The process is thenrepeated to generate reciprocating motion of a member attached to thepiston. The device is like an internal combustion engine wherein thefuel is a fluid in a sealed chamber that expands rapidly when highenergy light such as laser energy is applied to the fluid. The energygenerated by the optical device is utilized to operate a device in thewellbore. The downhole device may be any suitable device, including avalve, fluid control device, packer, sliding sleeve, safety valve, andan anchor. The motion energy generated by the fiber optic devices may beused to operate a generator to generate electrical power downhole whichpower is then utilized to charge batteries downhole or to directlyoperate a downhole device and/or to provide power to sensors in thewellbore. A plurality of such fiber optic devices may be utilized toincrease the energy generated. The devices may also be used as a pump tocontrol the supply of fluids and chemicals in the wellbore.

[0022] Examples of the more important features of the invention havebeen summarized rather broadly in order that the detailed descriptionthereof that follows may be better understood, and in order that thecontributions to the art may be appreciated. There are, of course,additional features of the invention that will be described hereinafterand which will form the subject of the claims appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

[0023] For a detailed understanding of the present invention, referenceshould be made to the following detailed description of the preferredembodiment, taken in conjunction with the accompanying drawings, inwhich like elements have been given like numerals, wherein:

[0024]FIG. 1 shows a schematic illustration of an elevational view of amulti-lateral wellbore and placement of fiber optic sensors therein.

[0025]FIG. 1A shows the use of a robotic device for deployment of thefiber optic sensors.

[0026]FIG. 2 is a schematic illustration of a wellbore system wherein afluid conduit along a string placed in the wellbore is utilized foractivating a hydraulically-operated device and for deploying a fiberoptic cable having a number of sensors along its length according to onepreferred embodiment of the present invention.

[0027]FIG. 3 shows a schematic diagram of a producing well wherein afiber optic cable with sensors is utilized to determine the health ofdownhole devices and to make measurements downhole relating to suchdevices and other downhole parameters.

[0028]FIG. 4 is a schematic illustration of a wellbore system wherein apermanently installed electrically-operated device is operated by afiber optic based system.

[0029]FIG. 5 is a schematic representation of an injection wellillustrating a plurality of sensors mounted therein.

[0030]FIG. 6 is a schematic representation illustrating both aninjection well and a production well having sensors and a flood frontrunning between the wells.

[0031]FIG. 7 is a schematic representation similar to FIG. 6 butillustrating fluid loss through unintended fracturing.

[0032]FIG. 8 is a schematic representation of an injection productionwell system where the wells are located on either side of a fault.

[0033]FIG. 9 is a schematic illustration of a chemical injectionmonitoring and control system utilizing a distributed sensor arrangementand downhole chemical monitoring sensor system in accordance with thepresent invention.

[0034]FIG. 10 is a schematic illustration of a fiber optic sensor systemfor monitoring chemical properties of produced fluids.

[0035]FIG. 11 is a schematic illustration of a fiber optic sol gelindicator probe for use with the sensor system of FIG. 10.

[0036]FIG. 12 is a schematic illustration of a surface treatment systemin accordance with the present invention.

[0037]FIG. 13 is a schematic of a control and monitoring system for thesurface treatment system of FIG. 12.

[0038]FIG. 14 is a schematic illustration of a wellbore system whereinelectric power is generated downhole utilizing a light cell for use inoperating sensors and devices downhole.

[0039] FIGS. 15A-15C show the power section of fiber optic devices foruse in the system of FIG. 1.

[0040]FIG. 16 is a schematic illustration of a wellbore with acompletion string having a fiber optic energy generation device foroperating a series of devices downhole.

[0041] FIGS. 17A-17C show certain configurations for utilizing the fiberoptic devices to produce the desired energy.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

[0042] The various concepts of the present invention will be describedin reference to FIGS. 1-17, which show a schematic illustrations ofwellbores utilizing fiber optic-based sensors and operating devices.

[0043]FIG. 1 shows an exemplary main or primary wellbore 12 formed fromthe earth surface 14 and lateral wellbores 16 and 18 formed from themain wellbore 18. For the purpose of explanation, and not as anylimitation, the main wellbore 18 is partially formed in a producingformation or pay zone I and partially in a non-producing formation ordry formation II. The lateral wellbore 16 extends from the main wellboreat a juncture 22 into the producing formation I, while the lateralwellbore 16 extends from the main wellbore 12 at juncture 24 into asecond producing formation III. For the purposes of this illustrationonly, the wellbores herein are shown as being drilled on land; however,this invention is equally applicable to offshore wellbores. It should benoted that all wellbore configurations shown and described herein are toillustrate the present invention and are not be construed to limit theinventions claimed herein.

[0044] In one application, a number of fiber optic sensors 40 are placedin the wellbore 12. A single or a plurality of fiber optic strings orsegments, each such segment containing a plurality of spaced apart fiberoptic sensors 40 may be used to install the desired number of fiberoptic sensors 40 in the wellbore 12. As an example, FIG. 1 shows twoserially coupled segments 41 a and 41 b, each containing a plurality ofspaced apart fiber optic sensors 40. A light source and detector (LS/D)46 a coupled to an end 49 segment 41 a is disposed in the wellbore 12 totransmit light energy to sensors 40 and to receiver signals from thesensors 40. A data acquisition unit (DA) 48 a is disposed downhole tocontrol the operation of the sensors 40, process downhole sensor signalsand data, and to communicate with other equipment and devices, includingdevices in the wellbores or at the surface shown below in FIGS. 2-17.

[0045] Alternatively, a light source 46 b and the data acquisition andprocessing unit 48 b may be placed on the surface 14. Similarly, fiberoptic sensor strings 45 may be disposed in other wellbores in thesystem, such as wellbores 16 and wellbore 18. A single light source,such as light source 46 a or 46 b may be used for all fiber opticsensors int he various wellbores, such as shown by the dotted line 70.Alternatively, multiple sources and data acquisition units may be useddownhole, at the surface, or in combination. Since the same sensor maymake different types of measurements, the data acquisition unit 48 a or48 b is programmed to multiplex the measurements. Multiplexingtechniques are well known in the art and are thus not described indetail herein. The data acquisition unit 46 a may be programmed tocontrol the downhole sensors autonomously or upon receiving commandsignals from the surface or a combination of these methods.

[0046] The sensors 40 may be installed in the wellbores 12,16 and 18before or after installing casings in the wellbores, such as casings 52shown installed in the wellbore 12. This may be accomplished byconnecting the strings 41 a and 41 b along the inside casings 52. Insuch a method, the strings 41 a and 41 b are preferably connectedend-to-end at the surface to ensure proper connections of the couplings42. The fiber optic sensors 40 and/or strings 41 a and 41 b may bedeployed or installed by conveying on coil tubing or pipes or otherknown methods. Alternatively, the fiber optic sensors may be conveyedand installed by robotics devices. This is illustrated in FIG. 1A wherea robotic device 62 is shown with a string of sensors 64 attached to it.The robotic device proceeds down the wellbore 12 having a casing 52therein to the position indicated by 62′, deploying the string ofsensors in the position indicated by 64′. In addition to installingsensors, the robotic device 64 may also perform other functions, such asmonitoring the performance of the sensors, and communicating with otherdevices such as the DA, the LS/D and other downhole devices describedbelow. The robotic devices may also be utilized to replace a sensor,conduct repairs and to retrieve the sensors or strings to the surface.Alternatively, the fiber optic sensors 40 may be placed in the casing 52at the surface while individual casing sections (which are typicallyabout forty feet long) are joined prior to conveying the casing sectionsinto the borehole. Stabbing techniques for joining casing or tubingsections are known in the art and are preferred over rotational jointsbecause stabbing generally provides better alignment of the endcouplings 42 and also because it allows operators to test and inspectoptical connections between segments for proper two-way transmission oflight energy through the entire string 41.

[0047] In the system shown in FIG. 1, a plurality of fiber optic sensors40 are installed spaced apart in one or more wellbores, such aswellbores 12, 16 and 18. If desired, each fiber optic sensor can operatein more than one mode to provide a number of different measurements. Thlight source 46 a, and dat detection and acquisition system 48 a arepreferably placed downhole. Although each fiber optic sensor 40 providesmeasurements for multiple parameters, it is relatively small compared toindividual commonly used single measurement sensors, such as pressuresensors, strain gauges, temperature sensors, flow measurement devicesand acoustic sensors. This makes it possible to make a large number ofdifferent types of measurements utilizing relatively little spacedownhole. Installing data acquisition and processing devices or units 48a downhole allows making a large number of data computations andprocessing downhole, avoiding the need for transmitting large amounts ofdata to the surface. Installing the light source 46 a downhole allowslocating the source 46 a close to the sensors 40, which avoidstransmission of light over great distances from the surface. The datafrom the downhole acquisition system 48 a may be transmitted to thesurface by any suitable method including wireline connectors,electromagnetic telemetry, and acoustic methods. Still, in someapplications, it may be desirable to locate the light source 46 b and/orthe data acquisition and processing system 46 b at the surface. Also, insome cases, it may be more advantageous to partially process the datadownhole and partially at the surface.

[0048] Still referring to FIG. 1, any number of other sensors, generallydenoted herein by numeral 60 may be disposed in any of the wellbores 12,16 and 18. Such sensors may include sensors for determining theresistivity of fluids and formations, gamma ray sensors, andhydrophones. The measurements from the fiber optic sensors 40 andsensors 60 are combined to determine the various conditions downhole.For example, flow measurements from production zones and the resistivitymeasurements may be combined to determine water saturation or todetermine oil, gas and water content.

[0049] In one mode, the fiber optic sensors are permanently installed inthe wellbores at selected locations. In a producing wellbore, thesensors 40 continuously or periodically (as programmed) provide thepressure and/or temperature and/or fluid flow measurements. Suchmeasurements are preferably made for each producing zone in each of thewellbores. To perform certain types of reservoir analyses, it isrequired to know the temperature and pressure build rates in thewellbores. This requires measuring temperature and pressure at selectedlocations downhole over extended time periods after shutting down thewell at the surface. In prior art methods, the well is shut down, awireline tool is conveyed into the wellbore and positioned at onelocation in the wellbore. The tool continuously measures temperature andpressure and may provide other measurements, such as flow rates. Thesemeasurements are then utilized to perform reservoir analysis, which mayincluded determining the extent of the hydrocarbon reserves remaining ina field, flow characteristics of the fluid from the producing formation,water content, etc. The above described prior art methods do not providecontinuous measurements while the well is producing and require specialwireline tools to be conveyed into the borehole. The present invention,on the other hand, provides, in-situ measurements while the well isproducing. The fluid flow information from each zone is used todetermine the effectiveness of each producing zone. Decreasing flowrates over time indicate problems with the flow control devices, such asscreens and sliding sleeves, or clogging of the perforations and rockmatrix near the wellbore. This information is used to determine thecourse of action, which may include further opening or closing slidingsleeves to increase or decrease production rates, remedial work, such ascleaning or reaming operations, shutting down a particular zone, etc.This is discussed below in reference to FIGS. 2-13. The temperature andpressure measurements are used to continually monitor each productionzone and to update reservoir models. To make measurements determiningthe temperature and pressure buildup rates, the wellbores are shut downand the process of making measurements continues. This does not requiretransporting wireline tools to the location, something that can be veryexpensive at offshore locations and wellbores drilled in remotelocations. Furthermore, in-situ measurements and computed data can becommunicated to a central office or the offices of the logging andreservoir engineers via satellite. This continuous monitoring ofwellbores allows taking relatively quick action, which can significantlyimprove the hydrocarbon production and the life of the wellbore. Theabove described methods may also be taken for non-producing zones, suchas zone H, to aid in reservoir modeling, to determine the effect ofproduction from various wellbores on the field in which the wellboresare being drilled.

[0050]FIG. 2 is a schematic diagram of a wellbore system 100 accordingto one embodiment of the present invention. System 100 includes awellbore 102 having a surface casing 101 installed a short distance fromthe surface 104. After the wellbore 102 has been drilled to a desireddepth. A completion or production string 106 is conveyed into thewellbore 102. The string 106 includes at least one downhillhydraulically operable device 114 carried by a tubing 108 which tubingmay be a drill pipe, coiled tubing or production tubing. A fluid conduit110 having a desired inner diameter 111 is placed or attached either onthe outside of the string 106 (as shown in FIG. 2) or in the inside ofthe string (not shown). The conduit 110 is routed at a desired locationon the string 106 via a u-joint 112 so as to provide a smooth transitionfor returning the conduit 110 to the surface 104. A hydraulic connection124 is provided from the conduit 110 to the device 114 so that a fluidunder pressure can pass from the conduit 110 to the device 114.

[0051] After the string 106 has been placed or installed at a desireddepth in the wellbore 102, an optical fiber 112 is pumped inlet 130 aunder pressure by a source of fluid 130.

[0052] The optical fiber 122 passes through the entire length of theconduit 110 and returns to the surface 104 via outlet 130 b. The fiber122 is then optically coupled to a light source and recorder (ordetector) (LS/REC) 140. A data acquisition/signal processor (DA/SP) 142processes data/signal received via the optical fiber 122 and alsocontrols the operation of the light source and recorder 140.

[0053] The optical fiber 122 includes a plurality of sensors 120distributed along its length. Sensors 120 may include temperaturesensors, pressure sensors, vibration sensors or any other fiber opticsensor that can be placed on the fiber optic cable 122. Sensors 120 areformed int the cable during the manufacturing of the cable 122. Thedownhole device 114 may be any downhole fluid-activated device and maybe a valve, a sliding sleeve, a perforating device, a packer or anyother hydraulically-activated device. The downhill device is activatedby supplying fluid under pressure through the conduit 110. Details ofthe sensor arrangement were described above with reference to FIGS.1-1A.

[0054] Thus, the system 100 includes a hydraulic-control line in conduit110 carried on a string 106. The control line 110 receives fiber opticcable 122 throughout its length and is connected to surfaceinstrumentation 140 and 142 for distributed measurements of downholeparameters along its length, such as temperature, pressure, etc. Theconduit 106 also carries fluid under pressure from a source of fluidunder pressure 130 for operating a fluid-actuated device 114 such as asliding sleeve, connected to the line 110. The line 110 may be arrangeddownhole along the string 106 in a V or other convenient shape. Thefluid-actuated device 114 may also be a choke, fluid flow regulationdevice, packer, perforating gun or other completion and or productiondevice.

[0055] During the completion of the wellbore 102, the sensors 120provide useful measurements relating to their associated downholeparameters and the line 106 is used to actuate a downhole device. Thesensors 120 continue to provide information about the downholeparameters over time, as discussed above with reference to FIGS. 1-1A.

[0056] Another part of the invention is related to the control ofdownhole devices using optical fibers. FIG. 2 shows a schematic diagramof a producing well 202 that preferably with two electric submersiblepumps (“ESP”) 214 one for pumping the oil/gas 206 the surface 203 andthe other to pump any separated water back into a formation. Theformation fluid 206 flows from a producing zone 208 into the wellbore202 via perforations 207. Packers 210 a and 210 b installed below andabove the ESP 214 force the fluid 206 to flow to the surface 203 viapumps ESP 214. An oil water separator 250 separates the oil and waterand provide them to their respective pumps 214 a-214 b. A choke 252provides desired back pressure. An instrument package 260 and pressuresensor is installed in the pump string 218 to measure related parametersduring production. The present invention utilizes optical fiber withembedded sensors to provide measurements of selected parameters, such astemperature, pressure, vibration, flow rate as described below. ESPs 214run at very high voltage which is supplied from a high voltage source230 at the surface via a high voltage cable 224. Due to the high powercarried by the cable 224, electrical sensors are generally not placed onor along side the cable 224.

[0057] In one embodiment of the present invention as shown in FIG. 4, afiber optic cable 222 carrying sensors 220 is placed along the powercable 224. The fiber optic cable 222 is extended to below the ESPs 214to the sensors in the instrumentation package 260 and to provide controlto the devices, if desired. In one application, the sensors 220 measurevibration and temperature of the ESP 214. It is desirable to operate theESP at a low temperature and without excessive vibration. The ESP 214speed is adjusted so as to maintain one or both such parameters belowtheir predetermined maximum value or within their respectivepredetermined ranges. The fiber optic sensors are used in thisapplication to continuously or periodically determine the physicalcondition (health) of the ESP. The fiber optic cable 222 may be extendedor deployed below the ESP at the time of installing the productionstring 218 in the manner described with respect to FIG. 2. Such aconfiguration may be utilized to continuously measure downhillparameters, monitor the health of downhill devices and control downhilldevices.

[0058]FIG. 4 shows a schematic of a wellbore system 400 wherein apermanently installed electrically-operated device is operated by afiber optic based system. The system 400 includes a wellbore 402 and anelectrically-operated device 404 installed at a desired depth, which maybe a sliding sleeve, a choke, a fluid flow control device etc. Anelectric control unit 406 controls the operation of the device 404. Aproduction tubing 410 installed above the device 404 allows formationfluid to flow to the surface 401. During the manufacture of the string411 that includes the device 404 and the tubing 410, a conduit 422 isclamped along the length of the tubing 410 with clamps 421. An opticalcoupler 407 is provided at the electrical control unit 406 which canmate with a coupler fed through the conduit 422.

[0059] Either prior to or after placing the string 410 in the wellbore402, a fiber optic cable 421 is deployed in the conduit 422 so that acoupler 422 a at the cable 421 end would couple with the coupler 407 ofthe control unit 406. A light source 440 provides the light energy tothe fiber 422. A plurality of sensors 420 may be deployed along thefiber 422 as described before. A sensor preferably provided on the fiber422 determines the flow rate of formation fluid 414 flowing through thedevice 404. Command signals are sent by DA/SP 442 to activate the device404 via the fiber 422. These signals are detected by the control unit406, which in turn operate the device 404. This, in the configuration ofFIG. 4, fiber optics is used to provide two way communication betweendownhole devices and sensors and a surface unit and to operate downholedevices.

[0060] A particular application of the invention is in the control ofdownhole devices in secondary recovery operations. Referring to FIG. 5,one of ordinary skill in the art will appreciate a schematicrepresentation of an injection well 510. Also recognizable will be therepresentation of a flood front 520 which emanates from the injectionwell and is intended to progress toward a production well. This is alsowell represented in FIG. 6 of the present application. In the presentinvention at least one and, preferably, a plurality of sensors 512 arelocated permanently installed in the injection well and which areconnected via the electrical wire cabling or fiber optic cabling to aprocessor which may either be a permanent downhole processor or asurface processor. The system provides immediate real time informationregarding the condition of the fluid front having been injected into theformation by the injection well. By carefully monitoring parameters suchas conductivity, fluid density, pressure at the injection ports 514 orat the pump 516 (which while represented at the surface can bepositioned downhole as well), acoustics and fluorescence for biologicalactivity, one can ascertain significant information about the progressof the flood front such as whether the front has hit a barrier orwhether the front may have “fingered” resulting in a likely prematurebreakthrough. This information is extremely valuable to the operator inorder to allow remedial measures to prevent occurrences that would bedetrimental to the efficiency of the flooding operation. Remedialactions include the opening or closing of chokes or other valves inincrements or completely in order to slow down particular areas ofinjection or increase the speed of particular areas of injection inorder to provide the most uniform flood front based upon the sensedparameters. These remedial measures can be taken either by personnel atthe surface directing such activity or automatically upon command by thesurface controller/processor on downhole processing unit 518. Thesensors contemplated herein may be in the injection well or in both theinjection well and the production well. They are employed in severaldifferent methods to obtain information such as that indicated above.

[0061] Control is further heightened in an alternate embodiment byproviding a link between downhole sensors in the production well to thedownhole sensors in the injection well as well as a connection to theflow control tools in both wells. By providing the operable connectionsto all of these parts of the system the well can actually run itself andprovide the most efficient oil recovery based upon the creation andmaintenance of a uniform flood front. It will be understandable at thispoint to one of ordinary skill in the art that the flood front can beregulated from both sides of FIG. 2 i.e., the injection well and theproduction well by opening production well valves in areas where theflood front is lagging while closing valves in areas where the floodfront is advancing.

[0062] Complementary to this, the fluid injection valves e.g., slidingor rotating sleeves, etc. would be choked or closed where the floodfront is advancing quickly and opened more where the flood front isadvancing slowly. This seemingly complex set of circumstances is easilycontrolled by the system of the invention and rapidly remedies anyabnormalities in the intended flood profile. Sweep efficiency of thesteam or other fluid front is greatly enhanced by the system of theinvention. All of the sensors contemplated in the production well andthe injection well are, preferably, permanently installed downholesensors which are connected to processors and/to one another byelectrical cabling or fiber optic cabling.

[0063] In another embodiment of the invention, illustrated schematicallyin FIG. 7, downhole sensors measure strain induced in the formation bythe injected fluid. Strain is an important parameter for avoidingexceeding the formation parting pressure or fracture pressure of theformation with the injected fluid. By avoiding the opening of orwidening of natural pre-existing fractures large unswept areas of thereservoir can be avoided. The reason this information is important inthe regulation of pressure of the fluid to avoid such activity is thatwhen pressure opens fractures or new fractures are created there is apath of much less resistance for the fluid to run through. Thus asstated earlier, since the injection fluid will follow the path of leastresistance it would generally run in the fractures and around areas ofthe reservoir that need to be swept. Clearly this substantially reducesits efficiency. The situation is generally referred to in the art as an“artificially high permeability channel.” Another detriment to such acondition is the uncontrolled loss of injected fluids. This is clearly aloss of oil due to the reduced efficiency of the sweep and additionallymay function as an economic drain due to the loss of expensive fluids.

[0064]FIG. 7 schematically illustrates the embodiment and the conditionset forth above by illustrating an injection well 550 and a productionwell 560. Fluid 552 is illustrated escaping via the unintended fracturefrom the formation 554 into the overlying gas cap level 556 and theunderlying water table 561 and it is evident to one of ordinary skill inthe art that the fluid is being lost in this location. The condition isavoided by the invention by using pressure sensors to limit theinjection fluid pressure as described above. The rest of the fluid 552is progressing as it is intended to through the formation 554. In orderto easily and reliably determine what the stress is in the formation554, acoustic sensors 556 are located in the injection well 550 atvarious points therein. Acoustic sensors which are well suited to thetask to which they will be put in the present invention are commerciallyavailable from Systems Innovations, Inc., Spectris Corporation andFalmouth Scientific, Inc. The acoustic sensors pick up sounds generatedby stress in the formation which propagate through the reservoir fluidsor reservoir matrix to the injection well. In general, higher soundlevels would indicate severe stress in the formation and should generatea reduction in pressure of the injected fluid whether by automaticcontrol or by technician control. A data acquisition system 558 ispreferable to render the system extremely reliable and system 558 may beat the surface where it is illustrated in the schematic drawing or maybe downhole. Based upon acoustic signals received the system of theinvention, preferably automatically, although manually is workable,reduces pressure of the injected fluid by reducing pump pressure.Maximum sweep efficiency is thus obtained.

[0065] In yet another embodiment of the invention, as schematicallyillustrated in FIG. 8, acoustic generators and receivers are employed todetermine whether a formation which is bifurcated by a fault is sealedalong the fault or is permeable along the fault. It is known by one ofordinary skill in the art that different strata within a formationbifurcated by a fault may have some zones that flow and some zones thatare sealed; this is the illustration of FIG. 8. Referring directly toFIG. 8, injection well 570 employs a plurality of sensors 572 andacoustic generators 574 which, most preferably, alternate withincreasing depth in the wellbore. In production well 580, a similararrangement of sensors 572 and acoustic generators 574 are positioned.The sensors and generators are preferably connected to processors whichare either downhole or on the surface and preferably also connect to theassociated production or injection well. The sensors 572 can receiveacoustic signals that are naturally generated in the formation,generated by virtue of the fluid flowing through the formation from theinjection well and to the production well and also can receive signalswhich are generated by signal generators 574. Where signal generators574 generate signals, the reflected signals that are received by sensors572 over a period of time can indicate the distance and acoustic volumethrough which the acoustic signals have traveled. This is illustrated inarea A of FIG. 8 in that the fault line 575 is sealed between area A andarea B on the figure. This is illustrated for purposes of clarity onlyby providing circles 576 along fault line 575. Incidentally, the areasof fault line 575 which are permeable are indicated by hash marks 577through fault line 575. Since the acoustic signal represented by arrowsand semi-curves and indicated by numeral 578 cannot propagate throughthe area C of the drawing which bifurcates area A from area B on theleft side of the drawing, that signal will bounce and it then can bepicked up by sensor 572. The time delay, number and intensity ofreflections and mathematical interpretation which is common in the artprovides an indication of the lack of pressure transmissivity betweenthose two zones. Additionally this pressure transmissivity can beconfirmed by the detection by said acoustic signals by sensors 572 inthe production well 580. In the drawing the area directly beneath area Ais indicated as area E is permeable to area B through fault 575 becausethe region D in that area is permeable and will allow flow of the floodfront from the injection well 570 through fault line 575 to theproduction well 580. Acoustic sensors and generators can be employedhere as well since the acoustic signal will travel through the area Dand, therefore, reflection intensity to the receivers 572 will decrease.Time delay will increase. Since the sensors and generators are connectedto a central processing unit and to one another it is a simple operationto determine that the signal, in fact, traveled from one well to theother and indicates permeability throughout a particular zone. Byprocessing the information that the acoustic generators and sensors canprovide the injection and production wells can run automatically bydetermining where fluids can flow and thus opening and closing valves atrelevant locations on the injection well and production well in order toflush production fluid in a direction advantageous to run through a zoneof permeability along the fault.

[0066] Other information can also be generated by this alternate systemof the invention since the sensors 572 are clearly capable of receivingnot only the generated acoustic signals but naturally occurring acousticwaveforms arising from both the flow of the injected fluids as theinjection well and from those arising within the reservoirs in result ofboth fluid injection operations and simultaneous drainage of thereservoir in resulting production operations. The preferred permanentdeployment status of the sensors and generators of the invention permitand see to the measurements simultaneously with ongoing injectionflooding and production operations. Advancements in both acousticmeasurement capabilities and signal processing while operating theflooding of the reservoir represents a significant, technologicaladvance in that the prior art requires cessation of theinjection/production operations in order to monitor acoustic parametersdownhole. As one of ordinary skill in the art will recognize thecessation of injection results in natural redistribution of the activeflood profile due primarily to gravity segregation of fluids andentropic phenomena that are not present during active floodingoperations. This clearly also enhances the possibility of prematurebreakthrough, as oil migrates to the relative top of the formation andthe injected fluid, usually water, migrates to the relative bottom ofthe formation, there is a significant possibility that the water willactually reach the production well and thus further pumping of steam orwater will merely run underneath the layer of oil at the top of theformation and the sweep of that region would be extremely difficultthereafter.

[0067] In yet another embodiment of the invention fiber optics areemployed (similar to those disclosed in the U.S. application Ser. No.60/048,989 filed on Jun. 9, 1997 (which is fully incorporated herein byreference) to determine the amount of and/or presence of biofoulingwithin the reservoir by providing a culture chamber within the injectionor production well, wherein light of a predetermined wavelength may beinjected by a fiber optical cable, irradiating a sample determining thedegree to which biofouling may have occurred. As one of ordinary skillin the art will recognize, various biofouling organisms will have theability to fluoresce at a given wavelength, that wavelength oncedetermined, is useful for the purpose above stated.

[0068] In another embodiment of the invention, the flood front ismonitored from the “back” employing sensors installed in the injectionwell. The sensors which are adequately illustrated in FIGS. 5 and 6provide acoustic signals which reflect from the water/oil interface thusproviding an accurate picture in a moment in time of thethree-dimensional flood front. Taking pictures in 4-D i.e., threedimensions over real time provides an accurate format of the densityprofile of the formation due to the advancing flood front. Thus, aparticular profile and the relative advancement of the front can beaccurately determined by the density profile changes. It is certainlypossible to limit the sensors and acoustic generators to the injectionwell for such a system, however it is even more preferable to alsointroduce sensors and acoustic generators in the production well towardwhich the front is moving thus allowing an immediate double check of thefluid front profile. That is, acoustic generators on the production wellwill reflect a signal off the oil/water interface and will provide anequally accurate three-dimensional fluid front indicator. The indicatorsfrom both sides of the front should agree and thus provides an extremelyreliable indication of location and profile.

[0069] Referring now to FIG. 9, the distributed fiber optic sensors ofthe type described above are also well suited for use in a productionwell where chemicals are being injected therein and there is a resultantneed for the monitoring of such a chemical injection process so as tooptimize the use and effect of the injected chemicals. Chemicals oftenneed to be pumped down a production well for inhibiting scale, paraffinsand the like as well as for other known processing applications andpretreatment of the fluids being produced. Often, as shown in FIG. 9,chemicals are introduced in an annulus 600 between the production tubing602 and the casing 604 of a well 606. The chemical injection (shownschematically at 608) can be accomplished in a variety of known methodssuch as in connection with a submersible pump (as shown for example inU.S. Pat. No. 4,582,131, assigned to the assignee hereof andincorporated herein by reference) or through an auxiliary lineassociated with a cable used with an electrical submersible pump (suchas shown for example in U.S. Pat. No. 5,528,824, assigned to theassignee hereof and incorporated herein by reference).

[0070] In accordance with an embodiment of the present invention, one ormore bottomhole sensors 610 are located in the producing zone forsensing a variety of parameters associated with the producing fluidand/or interaction of the injected chemical and the producing fluid.Thus, the bottomhole sensors 610 will sense parameters relative to thechemical properties of the produced fluid such as the potential ioniccontent, the covalent content, pH level, oxygen levels, organicprecipitates and like measurements. Sensors 610 can also measurephysical properties associated with the producing fluid and/or theinteraction of the injected chemicals and producing fluid such as theoil/water cut, viscosity and percent solids. Sensors 610 can alsoprovide information related to paraffin and scale build-up, H₂S contentand the like.

[0071] Bottomhole sensors 610 preferably communicate with and/or areassociated with a plurality of distributed sensors 612 which arepositioned along at least a portion of the wellbore (e.g., preferablythe interior of the production tubing) for measuring pressure,temperature and/or flow rate as discussed above in connection withFIG. 1. The present invention is also preferably associated with asurface control and monitoring system 614 and one or more known surfacesensors 615 for sensing parameters related to the produced fluid; andmore particularly for sensing and monitoring the effectiveness oftreatment rendered by the injected chemicals. The sensors 615 associatedwith surface system 614 can sense parameters related to the content andamount of, for example, hydrogen sulfide, hydrates, paraffins, water,solids and gas.

[0072] Preferably, the production well disclosed in FIG. 9 hasassociated therewith a so-called “intelligent” downhole control andmonitoring system which may include a downhole computerized controller618 and/or the aforementioned surface control and monitoring system 614.This control and monitoring system is of the type disclosed in U.S. Pat.No. 5,597,042, which is assigned to the assignee hereof and fullyincorporated herein by reference. As disclosed in U.S. Pat. No.5,597,042, the sensors in the “intelligent” production wells of thistype are associated with downhole computer and/or surface controllerswhich receive information from the sensors and based on thisinformation, initiate some type of control for enhancing or optimizingthe efficiency of production of the well or in some other way effectingthe production of fluids from the formation. In the present invention,the surface and/or downhole computers 614, 618 will monitor theeffectiveness of the treatment of the injected chemicals and based onthe sensed information, the control computer will initiate some changein the manner, amount or type of chemical being injected. In the systemof the present invention, the sensors 610 and 612 may be connectedremotely or in-situ.

[0073] In a preferred embodiment of the present invention, thebottomhole sensors comprise fiber optic chemical sensors. Such fiberoptic chemical sensors preferably utilize fiber optic probes which areused as a sample interface to allow light from the fiber optic tointeract with the liquid or gas stream and return to a spectrometer formeasurement. The probes are typically composed of sol gel indicators.Sol gel indicators allow for on-line, real time measurement and controlthrough the use of indicator materials trapped in a porous, sol gelderived, glass matrix. Thin films of this material are coated ontooptical components of various probe designs to create sensors forprocess and environmental measurements. These probes provide increasedsensitivity to chemical species based upon characteristics of thespecific indicator. For example, sol gel probes can measure with greataccuracy the pH of a material and sol gel probes can also measure forspecific chemical content. The sol gel matrix is porous, and the size ofthe pores is determined by how the glass is prepared. The sol gelprocess can be controlled so as to create a sol gel indicator compositewith pores small enough to trap an indicator in the matrix but largeenough to allow ions of a particular chemical of interest to pass freelyin and out and react with the indicator. An example of suitable sol gelindicator for use in the present invention is shown in FIGS. 10 and 11.

[0074] Referring to FIGS. 10 and 11, a probe is shown at 616 connectedto a fiber optic cable 618 which is in turn connected both to a lightsource 620 and a spectrometer 622. As shown in FIG. 11, probe 616includes a sensor housing 624 connected to a lens 626. Lens 626 has asol gel coating 628 thereon which is tailored to measure a specificdownhole parameter such as pH or is selected to detect the presence,absence or amount of a particular chemical such as oxygen, H₂S or thelike.

[0075] Attached to and spaced from lens 626 is a mirror 630. During use,light from the fiber optic cable 618 is collimated by lens 626 whereuponthe light passes through the sol gel coating 628 and sample space 632.The light is then reflected by mirror 630 and returned to the fiberoptical cable. Light transmitted by the fiber optic cable is measured bythe spectrometer 622. Spectrometer 622 (as well as light source 620) maybe located either at the surface or at some location downhole. Based onthe spectrometer measurements, a control computer 614, 616 will analyzethe measurement and based on this analysis, the chemical injectionapparatus 608 will change the amount (dosage and concentration), rate ortype of chemical being injected downhole into the well. Information fromthe chemical injection apparatus relating to amount of chemical left instorage, chemical quality level and the like will also be sent to thecontrol computers. The control computer may also base its controldecision on input received from surface sensor 615 relating to theeffectiveness of the chemical treatment on the produced fluid, thepresence and concentration of any impurities or undesired by-productsand the like.

[0076] In addition to the bottomhole sensors 610 being comprised of thefiber optic sol gel type sensors, in addition, the distributed sensors612 along production tubing 602 may also include the fiber opticchemical sensors (sol gel indicators) of the type discussed above. Inthis way, the chemical content of the production fluid may be monitoredas it travels up the production tubing if that is desirable.

[0077] The permanent placement of the sensors 610, 612 and controlsystem 617 downhole in the well leads to a significant advance in thefield and allows for real time, remote control of chemical injectionsinto a well without the need for wireline device or other wellinterventions.

[0078] In accordance with the present invention, a novel control andmonitoring system is provided for use in connection with a treatingsystem for handling produced hydrocarbons in an oilfield. Referring toFIG. 12, a typical surface treatment system used for treating producedfluid in oil fields is shown. As is well known, the fluid produced fromthe well includes a combination of emulsion, oil, gas and water. Afterthese well fluids are produced to the surface, they are contained in apipeline known as a “flow line”. The flow line can range in length froma few feet to several thousand feet. Typically, the flow line isconnected directly into a series of tanks and treatment devices whichare intended to provide separation of the water in emulsion from the oiland gas. In addition, it is intended that the oil and gas be separatedfor transport to the refinery.

[0079] The produced fluids flowing in the flow line and the variousseparation techniques which act on these produced fluids lead to seriouscorrosion problems. Presently, measurement of the rate of corrosion onthe various metal components of the treatment systems such as the pipingand tanks is accomplished by a number of sensor techniques includingweight loss coupons, electrical resistance probes,electrochemical—linear polarization techniques, electrochemical noisetechniques and AC impedance techniques. While these sensors are usefulin measuring the corrosion rate of a metal vessel or pipework, thesesensors do not provide any information relative to the chemicalsthemselves, that is the concentration, characterization or otherparameters of chemicals introduced into the treatment system. Thesechemicals are introduced for a variety of reasons including corrosioninhibition and emulsion breakdown, as well as scale, wax, asphaltene,bacteria and hydrate control.

[0080] In accordance with an important feature of the present invention,sensors are used in chemical treatment systems of the type disclosed inFIG. 12 which monitors the chemicals themselves as opposed to theeffects of the chemicals (for example, the rate of corrosion). Suchsensors provide the operator of the treatment system with a real timeunderstanding of the amount of chemical being introduced, the transportof that chemical throughout the system, the concentration of thechemical in the system and like parameters. Examples of suitable sensorswhich may be used to detect parameters relating to the chemicalstraveling through the treatment system include the fiber optic sensordescribed above with reference to FIGS. 10 and 11 as well as other knownsensors such as those sensors based on a variety of technologiesincluding ultrasonic absorption and reflection, laser-heated cavityspectroscopy (LIMS), X-ray fluorescence spectroscopy, neutron activationspectroscopy, pressure measurement, microwave or millimeter wave radarreflectance or absorption, and other optical and acoustic (i.e.,ultrasonic or sonar) methods. A suitable microwave sensor for sensingmoisture and other constituents in the solid and liquid phase influentand effluent streams is described in U.S. Pat. No. 5,455,516, all of thecontents of which are incorporated herein by reference. An example of asuitable apparatus for sensing using LIBS is disclosed in U.S. Pat. No.5,379,103 all of the contents of which are incorporated herein byreference. An example of a suitable apparatus for sensing LIMS is theLASMA Laser Mass Analyzer available from Advanced Power Technologies,Inc. of Washington, D.C. An example of a suitable ultrasonic sensor isdisclosed in U.S. Pat. No. 5,148,700 (all of the contents of which areincorporated herein by reference). A suitable commercially availableacoustic sensor is sold by Entech Design, Inc., of Denton, Tex. underthe trademark MAPS®. Preferably, the sensor is operated at amultiplicity of frequencies and signal strengths. Suitable millimeterwave radar techniques used in conjunction with the present invention aredescribed in chapter 15 of Principles and Applications of MillimeterWave Radar, edited by N. C. Currie and C. E. Brown, Artecn House,Norwood, Mass. 1987. The ultrasonic technology referenced above can belogically extended to millimeter wave devices.

[0081] While the sensors may be utilized in a system such as shown inFIG. 12 at a variety of locations, the arrows numbered 700, through 716indicate those positions where information relative to the chemicalintroduction would be especially useful.

[0082] Referring now to FIG. 13, the surface treatment system of FIG. 12is shown generally at 720. In accordance with the present invention, thechemical sensors (i.e. 700-716) will sense, in real time, parameters(i.e., concentration and classification) related to the introducedchemicals and supply that sensed information to a controller 722(preferably a computer or microprocessor based controller). Based onthat sensed information monitored by controller 722, the controller willinstruct a pump or other metering device 724 to maintain, vary orotherwise alter the amount of chemical and/or type of chemical beingadded to the surface treatment system 720 The supplied chemical fromtanks 726, 726′ and 726″ can, of course, comprise any suitable treatmentchemical such as those chemicals used to treat corrosion, break downemulsions, etc. Examples of suitable corrosion inhibitors include longchain amines or aminidiazolines. Suitable commercially availablechemicals include CronoxÔ which is a corrosion inhibitor sold by BakerPetrolite, a division of Baker-Hughes, Incorporated, of Houston, Tex.

[0083] Thus, in accordance with the control and monitoring system ofFIG. 13, based on information provided by the chemical sensors 700-716,corrective measures can be taken for varying the injection of thechemical (corrosion inhibitor, emulsion breakers, etc.) into the system.The injection point of these chemicals could be anywhere upstream of thelocation being sensed such as the location where the corrosion is beingsensed. Of course, this injection point could include injectionsdownhole. In the context of a corrosion inhibitor, the inhibitors workby forming a protective film on the metal and thereby prevent water andcorrosive gases from corroding the metal surface. Other surfacetreatment chemicals include emulsion breakers which break the emulsionand facilitate water removal. In addition to removing or breakingemulsions, chemicals are also introduced to break out and/or removesolids, wax, etc. Typically, chemicals are introduced so as to providewhat is known as a base sediment and water (B.S. and W.) of less than1%.

[0084] In addition to the parameters relating to the chemicalintroduction being sensed by chemical sensors 700-716, the monitoringand control system of the present invention can also utilize knowncorrosion measurement devices as well including flow rate, temperatureand pressure sensors. These other sensors are schematically shown inFIG. 13 at 728 and 730. The present invention thus provides a means formeasuring parameters related to the introduction of chemicals into thesystem in real time and on line. As mentioned, these parameters includechemical concentrations and may also include such chemical properties aspotential ionic content, the covalent content, pH level, oxygen levels,organic precipitates and like measurements. Similarly, oil/water cutviscosity and percent solids can be measured as well as paraffin andscale build-up, H₂S content and the like.

[0085] Another aspect of the invention is the ability to transmitoptical energy downhole and convert it to another form of energysuitable for operation of downhole devices. FIG. 14 shows a wellbore 802with a production string 804 having one or more electrically-operated oroptically-operated devices, generally denoted herein by numeral 850 andone or more downhole sensors 814. The string 804 includes batteries 812which provide electrical power to the devices 850 and sensors 814. Thebatteries are charged by generating power downhole by turbines (notshown) or by supplying power for the surface via a cable (not shown).

[0086] In the present invention a light cell 810 is provided in thestring 804 which is coupled to an optical fiber 822 that has one or moresensors 820 associated therewith. A light source 840 at the surfaceprovides light to the light cell 810 which generates electricity whichcharges the downhill batteries 812. The light cell 810 essentiallytrickle charges the batteries. In many applications the downholedevices, such as devices 850, are activated infrequently. Tricklecharging the batteries may be sufficient and thus may eliminate the useof other power generation devices. In applications requiring greaterpower consumption, the light cell may be used in conjunction with otherpower generator devices.

[0087] Alternatively, if the device 850 is optically-activated the fiber822 is coupled to the device 850 as shown by the dotted line 822 a andis activated by supplying optical pulses from the surface unit 810. Thusin the configuration of FIG. 14, a fiber optics device is utilized togenerate electrical energy downhole, which is then used to charge asource, such as a battery, or operate a device. The fiber 822 is alsoused to provide two-way communication between the DA/SP 842 and downholesensors and devices.

[0088]FIG. 15 is a schematic illustration of a wellbore system 900utilizing the fiber optic energy producing devices according oneembodiment of the present invention. System 900 includes a wellbore 902having a surface casing 901 installed a relatively short depth 904 afrom the surface 904. After the wellbore 902 has been drilled to adesired depth, a completion or production string 906 is conveyed intothe wellbore 902. A fiber optic energy generation device 920 placed inthe string 906 generates mechanical energy. The operation of the fiberoptic device 920 is described in reference to FIGS. 15A-15C.

[0089] The fiber optic device 920A shown in FIG. 15A contains a sealedchamber 922 a containing a gas 923 which will expand rapidly whenoptical energy such as laser energy is applied to the gas 923. A piston924 a disposed in the device 920A moves outward when the gas 923expands. When the optical energy is not being applied to the gas 923; aspring 926 a or another suitable device coupled to a piston rod 925 aforces the piston 926 a back to its original position. The gas 923 isperiodically charged with the optical energy conveyed to the device 920a via an optical conductor or fiber 944. FIG. 15B shows the opticaldevice 920B wherein a spring 926 b is disposed within the enclosure 921to urge the piston 924 b back to its original position.

[0090] Referring back to FIG. 15, the outward motion of the member 925of the device 920 causes a valve 930 to open allowing the wellbore fluid908 at the hydrostatic pressure to enter through port 932. The valve 930is coupled to hydraulically-operated device 935 in a manner that allowsthe fluid 908 under pressure to enter the device 935 via the port 932.Thus, in the configuration of FIG. 15, fiber optic device 920 controlsthe flow of the fluid 908 at the hydrostatic pressure to thehydraulically-operated device 935. The device 935 may be a packer, fluidvalve, safety valve, perforating device, anchor, sliding sleeve etc. Theoperation of the device 920 is preferably controlled from the surface904, a light source LS 940 provides the optical energy to the device 908via the fiber 944. One or more sensors 927 may be provided to obtainfeedback relating to the downhole operations. The sensors 927 providemeasurements relating to the fluid flow, force applied to the valve 930,downhole pressures, downhole temperatures etc. The signals from sensors927 may be processed downhole or sent to the surface data acquisitionand processing unit 942 via the fiber 944.

[0091] An alternate embodiment of a light actuated transducer for use influid flow control is shown in FIG. 15C. The device 950 includes aphotovoltaic cell 960 and a bi-morph element fluid valve cell 970.Optical energy from an optical fiber 944 is connected by means ofoptical lead 946 to a photovoltaic cell 960. The photovoltaic cell 960upon excitation by light produces an electric current that is conveyedby lead 962 to a bimetallic strip (bi-morph element) 964. Passage ofcurrent through the bimetallic strip causes it to bend to position 9649and move a ball 980 that rests in a valve seat 976. Motion of the ball980 away from the seat to 980′ enables a fluid 982 to flow through theinlet port 972 in the bi-morph element fluid valve cell 970 and theoutlet port 974. Other arrangements of the bimetallic strip and thevalve arrangement would be familiar to those versed in the art. Thisillustrates equipment in which optical energy is converted first toelectrical energy and then to mechanical motion.

[0092] In yet another embodiment of the invention (not shown), theoptical energy is used to alter the physical properties of aphotosensitive material, such as a gel, that is incorporated in a flowcontrol device. Screens having a gravel pack are commonly used in oiland gas production to screen out particulate matter. In one embodimentof the invention, a photosensitive gel is used as the packing materialin the screen. Activation of the gel by optical energy changes thephysical characteristics of the gel, partially crystallizing it. Thismakes it possible to adjust the size of particles flowing through thescreen.

[0093]FIG. 16 shows a wellbore system 1000 wherein the fiber opticdevices 1020 are used to operate one or more downhole devices andwherein the pressurized fluid is supplied through a conduit which alsocarries the optical fiber to the devices 1020 from the surface 904. Avalve 1030 is operated by the fiber optic device 920 in the mannerdescribed above with reference to FIG. 15. Pressurized fluid 1032 from asource 1045 is supplied to the valve 1030 via a conduit 1010. Theconduit 1010 the optical fiber 1044 is pumped through the conduit froman the surface. Alternatively, the conduit 1010 containing the fiber1044 may be assembled at the surface and deployed into the wellbore withthe string 1006. To operate the device 1035, the fiber optic device 920is operated and the fluid 1032 under pressure is continuously suppliedto the valve 1030 via the conduit 1010, which activates or sets thedevice 1035. Other downhole devices 1050 b, 1050 c etc. may be disposedin the string 1006 or in the wellbore 1002. Each such device utilizesseparate fiber optic devices 920 and may utilize a common conduit 1010for the optical fiber 1044 and/or for the pressurized fluid 1032.

[0094]FIG. 17A shown a configuration utilizing multiple fiber opticdevices 1120 a-1120 c to generate rotary power. The devices 1120 a-1120c are similar to the devices 920 described above. Light energy ispreferably provided to such devices via a common optical fiber 1144. Thesource 940 operates the devices 1120 a-1120 c in a particular order witha predetermined phase difference. An address system (not shown) may beutilized to address the devices by signals generated for such devices,The piston arms 1127 a-1127 c are coupled to a cam shaft 1125 atlocations 1125 a-1125 c respectively, which rotates in the direction1136 to provide rotary power. The rotary power may be utilized for anydenied purpose, such as to operate a pump or a generator to generateelectrical power.

[0095]FIG. 17B-17C shows a configuration wherein the fiber optic devicesare used to pump fluids. The fiber optic devices 1182 a of FIG. 17Bcontains a firing cylinder 1184 a and a second cylinder 1184 b. Thesecond or hydraulic cylinder contains an outlet port 1183 b. Suitablefluid is supplied to the hydraulic cylinder via the inlet port 1183 a.When the device 1182 a is fired, the piston 1186 moves downward,blocking the inlet port 1183 a and simultaneously displacing the fluid1186 from the cylinder 1184 b via the outlet port 1183 b. The spring1185 forces the piston 1186 to return to its original position,uncovering the inlet port, until the next firing of the device 1182 a.In this manner the device 1182 a may be utilized to pump fluid. The flowrate is controlled by the firing frequency and the size of the fluidchamber 1184 b.

[0096]FIG. 17C shows two fiber optic devices 382 b and 382 c (similar tothe device 382 a) connected in series to pump a fluid. In thisconfiguration, when the device 382 b is fired, fluid 390 from thechannels 391 of the device 382 discharges into the chamber 391 b of thedevice 382 c via line 392. A one-way check valve allows the fluid toflow only in the direction of the device 382 c. The firing of the device382 c discharges the fluid from the chamber 391 b via line 394 to thenext stage.

[0097] While the foregoing disclosure is directed to the preferredembodiments of the invention, various modifications will be apparent tothose skilled in the art. It is intended that all variations within thescope and spirit of the appended claims be embraced by the foregoingdisclosure.

What is claimed is:
 1. Apparatus from monitoring and controllingdownhole equipment, comprising: (a) a hydraulic line extending into awellbore for supplying fluid under pressure downhole carried on thetubing; (b) a plurality of fiber optic sensors providing measurements ofa downhole parameter along the tubing; and; (c) ahydraulically-controlled device on the tubing and in fluid communicationwith the hydraulic line, wherein said hydraulic line provides both themonitoring of the downhole parameter and the control of thehydraulically-operated device.
 2. The apparatus of claim 1 wherein thefiber optic sensors and disposed inside the hydraulic line.
 3. Theapparatus of claim 1 wherein the hydraulic line is a return lineextending from a surface location to the hydraulically-operated device.4. The apparatus of claim 1 wherein the hydraulically-operated device isselected from a group consisting of (a) flow control device, (b) apacker, (c) a choke, (d) a perforating device, (e) an anchor, (f) acompletion device, and (g) a production device.
 5. The apparatus ofclaim 1 wherein the downhole parameter is one of (a) temperature, (b)pressure, (c) vibration, (d) acoustic measurement, (e) fluid flow, and(f) a fluid property.
 6. The apparatus of claim 1 wherein the pluralityof sensors include at least one of (a) temperature sensor, (b) pressuresensor, (c) acoustic sensor, (d) flow measurement sensor, and (f)vibration sensor.
 7. A method of monitoring a downhole parameter andcontrolling a hydraulically-operated device, comprising: (a) providing ahydraulically-operated device in a wellbore; (b) conveying a hydraulicline in downhole, said hydraulic supplying fluid under pressure to thehydraulically-operated device for controlling the operation of thehydraulically-operated device. (c) providing a fiber optic sensor in thehydraulic line for measuring a downhole parameter along the hydraulicline so that the same hydraulic line provides measurement for thedownhole parameter and the control of the hydraulically-operated device.8. A method of controlling production from a wellbore, comprising: (a)providing a producing string carrying an electrical submersible pump forpumping wellbore fluid to the surface, said string carrying a highvoltage line from a surface location to the pump or providing electricalpower to the pump; and (b) providing an optical fiber carrying at leastone fiber optic sensor along the high voltage lien for takingmeasurements of a wellbore parameter.
 9. The method of claim 8 whereinat least one fiber optic sensor is placed below the pump.
 10. The methodof claim 9, wherein the sensor below the pump is selected from a groupconsisting of a (a) pressure sensor, (b) temperature sensor, (c)vibration sensors, and (d) flow measurement sensor.
 11. The method ofclaim 8 further comprising controlling the operation of the electricalsubmersible pump in response to the downhole parameter.
 12. The methodof claim 11 wherein the downhole parameter is one of (a) temperature ofthe pump, (b) vibration of the pump, and (c) fluid flow by the pump. 13.An apparatus for monitoring the condition of an electric power linesupplying high electric power into a wellbore, comprising: (a) a conduitextending into the wellbore; (b) an electric powerline in the conduitcarrying high electric power to a location in the wellbore; and, (c) aplurality of fiber optic sensors distributed along and adjacent theelectric powerline, said fiber optic sensors providing measurementsrepresenting a physical condition of the electric powerline.
 14. Asystem for controlling a downhole device in a wellbore comprising: (a) afiber optic sensor in the wellbore providing measurements for a downholeparameter; (b) a source of power for supplying power to operate thedownhole device; and, (c) a controller providing signals responsive tothe fiber optic sensor measurements.
 15. The system of claim 14 whereinthe source of power is one of (a) operating the downhole device, (b)light energy and (c) hydraulic power.
 16. A downhole injectionevaluation system comprising: a) at least one downhole sensorpermanently disposed in an injection well for sensing at least oneparameter associated with injecting a fluid into a formation.
 17. Adownhole injection evaluation system as claimed in claim 16 wherein saidsystem further includes an electronic controller operably connected tosaid at least one downhole sensor.
 18. A downhole injection evaluationsystem as claimed in claim 17 wherein said at least one downhole sensoris operably connected to at least one production well sensor to providesaid electronic controller, operably connected to said at least onedownhole sensor and to said at least one production well sensor, withinformation from both sides of a fluid front moving between saidinjection well and said production well.
 19. A system for optimizinghydrocarbon production comprising: a) a production well; b) an injectionwell, said production well and said injection well being datatransmittably connected; c) at least one sensor located in either ofsaid injection well and said production well, said at least one sensorbeing capable of sensing at least one parameter associated with aninjection operation, said sensor being operably connected to acontroller for controlling injection in the injection well.
 20. Anautomatic injection/production system comprising: a) an injection wellhaving at least one sensor and at least one flow controller; b) aproduction well having at least one sensor and at least one flowcontroller; c) at least one system controller operably connected to saidsensors and said fluid controllers whereby said system controllerscontrols said flow controllers according to information received by saidsensors.
 21. A downhole injection evaluation system as claimed in claim17 wherein said system further includes at least one downhole acousticsignal generator whereby signals generated by said at least one signalgenerator reflect off a flood fluid/hydrocarbon interface and arereceived by said at least one downhole sensor.
 22. An injection wellhaving at least one fiber optic cable disposed therein in a locationadvantageous to irradiate a portion of the strata of the formationimmediately surrounding the well to measure fluorescence of bacteriapresent.
 23. A method for avoiding injection induced unintentionalfracture growth comprising: a) providing at least one acoustic sensor inan injection well; b) monitoring said at least one sensor; c) varyingpressure of a fluid being injected to avoid a predetermined thresholdlevel of acoustic activity received by said at least one sensor.
 24. Amethod for enhancing hydrocarbon production wherein at least oneinjection well and an associated production well include at least onesensor and at least one flow controller comprising: a) providing asystem capable of monitoring said at least one sensor in each of saidwells and controlling said at least one flow controller in each of saidwells in response thereto to optimize hydrocarbon production.
 25. Anapparatus for controlling chemical injection of a surface treatmentsystem for an oilfield well, comprising: (a) a chemical injecting deviceinjecting one or more chemicals into the treatment system for thetreatment of fluids produced from an oilfield well; (b) at least onechemical sensor associated with the treatment system for sensing atleast one parameter of the injected chemical or for sensing at least onechemical property of the fluids produced from the oilfield well; and (c)a control and monitoring system for controlling the chemical injectiondevice in response, at least in part, to information from said downholechemical sensor.
 26. The apparatus of claim 25 further comprising atleast one additional sensor distributed in said treatment system formeasuring at least one of pressure, temperature and flow, saiddistributed sensors communicating with said control system.
 27. Theapparatus of claim 26 wherein said distributed sensor comprises at leastone fiber optic sensor.
 28. The apparatus of claim 25 wherein saidcontrol system includes a computerized controller.
 29. The apparatus ofclaim 25 wherein said chemical sensor is a fiber optic sensor.
 30. Theapparatus of claim 29 wherein said fiber optic downhole chemical sensorincludes a probe which is sensitive to at least one selected chemicallyrelated parameter.
 31. The apparatus of claim 30 wherein said probeincludes a sol gel sensor.
 32. The apparatus of claim 6 wherein saidfiber optic downhole sensor includes a spectrometer in communicationwith said probe.
 33. A method of monitoring chemical injection into asurface treatment system of an oilfield well, comprising: (a) injectingone or more chemicals into the treatment system for the treatment offluids produced in the oilfield well; (b) sensing at least one chemicalproperty of the fluids in the treatment system (c) using at least onechemical sensor associated with the treatment system.
 34. The method ofclaim 33 wherein said chemical sensor is a fiber optic sensor.
 35. Themethod of claim 34 wherein said fiber optic chemical sensor includes aprobe which is sensitive to at least one selected chemically relatedparameter.
 36. The method of claim 35 wherein said probe includes a solgel sensor.
 37. A light actuated system for use in a wellbore,comprising: (a) a light actuated transducer in the wellbore, said lightactuated tranducer adapted to transform a physical state of a componentthereof upon application of optical energy; (b) an optical waveguideconveying the optical energy from a source thereof to the light actuatedtransducer, and (c) a control device in the wellbore operated at leastin part by the said change in the physical state of the component of thelight actuated transducer.
 38. The light actuated system of claim 37,wherein said transformation of the physical state is selected from theset consisting of (i) mechanical motion of the component, and (ii) achange in the physical properties of the component.
 39. The lightactuated system of claim 37 wherein the optical waveguide is one of (i)an optical fiber, and (ii) a fluid-filled waveguide.
 40. The lightactuated system of claim 37 wherein the control device is one of (i) afluid control device, (ii) an electronic power generation device, (iii)an electrical switching device, (iv) a fluid pressuring device, (v) adownhole light source, and (vi) an energy sensitive material thatchanges physical properties.
 41. The light actuated system of claim 40further comprising an end use device controlled at least in part by thecontrol device, said end use device being one of (i) flow controlequipment, (ii) lifting equipment, (iii) injection equipment, (iv)perforating equipment, (v) packer, (vi) fluid separating equipment,(vii) sensing equipment, (viii) pump, and (ix) fluid treatmentequipment.
 42. The light actuated system of claim 37 whereintransformation of the physical state includes the movement of a fluidand the source of the fluid is one of (i) a pressurized fluid suppliedfrom a surface location, (ii) pressurized fluid supplied from thesurface via a conduit carrying the optical waveguide to the lightactuated system, and (iii) wellbore fluid at hydrostatic pressure. 43.The light actuated system of claim 42 wherein the fluid is enclosed in achamber having a reciprocating piston therein, said piston reciprocatingdue to the expansion of the fluid upon application of optical energy.44. The light actuated system of claim 40 wherein the transformation ofthe physical state includes the conversion of the optical energy tomotion of a piezoelectric material carrying the electrical energy. 45.The light actuated system of claim 37 further comprising at least onesensor in the wellbore providing measurements of at least one selecteddownhole parameter.
 46. The light actuated system of claim 37 whereinthe downhole parameter is one of (a) temperature, (b) pressure, (c)vibration, (d) acoustic field, and (e) corrosion.
 47. The light actuatedsystem of claim 37 further comprising a plurality of fiber optic sensorsfor making distributed measurements.
 48. The light actuated system ofclaim 37 further comprising a processor adapted to provides signalsresponsive to downhole parameters for controlling a downhole device. 49.A method for producing formation fluids through a wellbore, comprising:(a) providing a light actuated transducer in the wellbore, said lightactuated transducer adapted to transform a physical state of a componentthereof upon application of optical energy; (b) providing a controldevice in the wellbore that is operated at least in part by said changein the physical state of the component of the light actuated transducer;and (c) supplying optical energy to the light actuated transducer,causing said light actuated transducer to change the physical state ofthe component thereof, thereby operating the control device.
 50. Themethod of claim 49 further comprising providing a conduit from thesurface to the light actuated transducer and the control device, saidconduit carrying an optical waveguide for supplying the optical energyto the light actuated transducer and providing a path for supplyingfluid under pressure to a device in the wellbore.
 51. The light actuatedsystem of claim 45 wherein the at least one sensor comprises a pluralityof spaced apart sensors.
 52. A method of generating electric power in awellbore, comprising: (a) placing a light cell at a desired depth in thewellbore, said light cell generating electric energy upon receivinglight energy; and (b) supplying light energy from a source thereof tothe light cell for generating the electrical energy downhole.
 53. Themethod of claim 52 further comprising charging and electric energystorage device in the wellbore with the electrical energy produced bythe light cell.
 54. The method of claim 53 further comprising providingan electrically-operated device in the wellbore and operating saiddevice utilizing the electrical energy from the storage device.
 55. Themethod of claim 54 wherein the electrically-operated device is selectedfrom the group consisting of a (a) sliding sleeve, (b) choke, and (c) aflow control device.
 56. The method of claim 52 further providing lightenergy to the light cell via optical fiber conveyed from the surface.57. The method of claim 7 wherein the hydraulically-operated device isselected from a group consisting of (a) flow control device, (b) apacker, (c) a choke, (d) a perforating device, (e) an anchor, (f) acompletion device, and (g) a production device.
 58. The method of claim7 wherein the downhole parameter is one of (a) temperature, (b)pressure, (c) vibration, (d) acoustic measurement, (e) fluid flow, and(f) a fluid property.
 59. The method of claim 7 wherein the fiber opticsensor is selected from the set consisting of (a) temperature sensor,(b) pressure sensor, (c) acoustic sensor, (d) flow measurement sensor,and (f) vibration sensor.